System and method for producing oil

ABSTRACT

The present invention provides a system and method for producing oil in which an ether-containing formulation is injected into a formation containing oil and an oil-immiscible formulation is injected into the formation, and oil is produced from the formation. The oil-immiscible formulation has a salt content of at most 5 wt. % and is comprised of water having a salt content of at most 5 wt. %.

The present application claims the benefit of U.S. Patent ApplicationNo. 61/570,664, filed Dec. 15, 2011, the entire disclosure of which ishereby incorporated by reference.

FIELD OF THE INVENTION

The present disclosure relates to systems and methods for producing oil.

BACKGROUND OF THE INVENTION

Enhanced Oil Recovery (EOR) may be used to increase oil recovery infields worldwide. There are three main types of EOR, thermal,chemical/polymer and gas injection, which may be used to increase oilrecovery from a reservoir, beyond what can be achieved by conventionalmeans—possibly extending the life of a field and boosting the oilrecovery factor.

Thermal enhanced recovery works by adding heat to the reservoir. Themost widely practiced form is a steam drive, which reduces oil viscosityso that it can flow to the producing wells. Chemical flooding increasesrecovery by reducing the capillary forces that trap residual oil.Polymer flooding improves the sweep efficiency of injected water.Miscible injection works in a similar way to chemical flooding—byinjecting a fluid that is miscible with the oil, trapped residual oilcan be recovered.

Referring to FIG. 1, there is illustrated prior art system 100. System100 includes underground formation 102, underground formation 104,underground formation 106, and underground formation 108. Productionfacility 110 is provided at the surface. Well 112 traverses formations102 and 104, and terminates in formation 106. The portion of formation106 is shown at 114. Oil and gas are produced from formation 106 throughwell 112, to production facility 110. Gas and liquid are separated fromeach other, gas is stored in gas storage 116 and liquid is stored inliquid storage 118.

WO 2008141051 discloses a system and a method for recovering oil and/orgas from an oil-bearing subterranean formation by injecting a miscibleenhanced oil recovery (“EOR”) formulation, which may comprise a dimethylether formulation, into the formation through a well located above theformation and producing oil and/or gas from the formation through awell. In one embodiment of the disclosed method, a quantity of themiscible EOR formulation is injected into an oil-bearing formationfollowed by injection of another component to force the miscible EORformulation across the formation. The component used to force themiscible EOR formulation across the formation may be an immiscible EORformulation, where the immiscible EOR formulation may include water ingas or liquid form, air, nitrogen, mixtures of two or more of thepreceding, or other immiscible EOR agents as are known in the art.

After injecting an ether-containing EOR formulation into a formation andmobilizing oil for production from the formation with theether-containing EOR formulation, residual oil may be left in theformation. The residual oil retains at least a portion of the ether fromthe ether-containing EOR formulation since ethers are miscible in theresidual oil. A portion of the ether trapped in the residual oil may berecovered by an immiscible EOR formulation used to force theether-containing formulation across the formation if the immiscible EORformulation contains water, however, a substantial portion of the ethermay be left in the residual oil if the ether is not particularlymiscible with the immiscible EOR formulation.

There is a need in the art for improved systems and methods for enhancedoil recovery utilizing an ether in an EOR formulation. In particular,there is a need in the art for improved systems and methods for enhancedoil recovery using an ether-containing solvent to improve recovery ofether trapped in residual oil in the formation after injection of anether-containing EOR formulation into the formation. The recovered ethermay be re-utilized in an EOR formulation for further recovery of oilfrom the formation.

SUMMARY OF THE INVENTION

In one aspect, the present invention is directed to a system forproducing oil from an underground formation comprising a first wellabove the formation; a mechanism to inject a formulation comprising anether containing from 2 to 6 carbons into the formation; a mechanism toinject an oil-immiscible formulation into the formation, where theoil-immiscible formulation has a salt content of at most 5 wt. % and iscomprised of water having at most 5 wt. % salt content; and a mechanismto produce oil from the formation, wherein at least one of the mechanismto inject the formulation comprising an ether containing from 2 to 6carbons, the mechanism to inject the oil-immiscible formulation, or themechanism to produce oil from the formation is located at the firstwell.

In another aspect, the present invention is directed to a method forproducing oil comprising injecting a formulation comprising an ethercontaining from 2 to 6 carbons into a formation containing oil;injecting an oil-immiscible formulation into the formation, where theoil-immiscible formulation comprises water having a salt content of lessthan 5 wt. %; and producing oil, an ether containing from 2 to 6carbons, and water from the formation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an oil and/or gas production system.

FIG. 2 a illustrates a well pattern.

FIGS. 2 b and 2 c illustrate the well pattern of FIG. 2 a duringenhanced oil recovery processes.

FIG. 2 d illustrates a well pattern.

FIGS. 3 a-3 d illustrate oil production systems.

FIG. 4 is a graph of the effect of salt concentration on the solubilityof DME in the aqueous phase at 6895 KPa.

FIG. 5 is a graph of the effect of salt concentration on thevapor-liquid equilibrium of DME (mol fraction (x)) with water at 50° C.

FIG. 6 is a graph of the effect of pressure in the liquid-liquid regionon the solubility of DME in NaCL brines at 50° C.

FIGS. 7 a and 7 b are graphs showing the CPA-SALT model prediction ofthe effect of salt on DME solubility (mol fraction (x)) in water (lines)compared to experimental data (symbols) at 30° C. FIG. 7 a shows fullscale of pressure and FIG. 7 b emphasizes vapor-liquid equilibria.

FIGS. 8 a and 8 b are graphs showing the CPA-SALT model prediction ofthe effect of salt on DME solubility (mol fraction (x)) in water (lines)compared to experimental data (symbols) at 50° C. FIG. 8 a shows fullscale of pressure and FIG. 8 b emphasizes vapor-liquid equilibria.

FIG. 9 is a graph showing the CPA-SALT model prediction of the effect ofsalt on DME solubility (mol fraction (x)) in water (lines) compared toexperimental data (symbols) at 80° C. and 120° C. for a 10 wt. % NaClbrine.

FIG. 10 is a graph showing the densities of the aqueous DME-Brine phaseat 30° C. (symbols represent the experimental data and the linesrepresent CPA-SALT model predictions).

FIG. 11 is a graph showing the Densities of the aqueous DME-Brine phaseat 50° C. (symbols represent experimental data and lines representCPA-SALT model predictions).

FIG. 12 is a graph showing the solubility of DME in Brines of VariousConcentrations v. Temperature at a Fixed Pressure of 6895 KPa (1000 psi)(symbols represent experimental data and lines represent CPA-SALT modelpredictions).

DETAILED DESCRIPTION OF THE INVENTION

The present invention provides a system and a method for enhanced oilrecovery from a formation containing oil using an ether-containingformulation comprising an ether containing from 2 to 6 carbon atoms tomobilize and produce oil from the formation, wherein the ether isrecovered from residual oil not mobilized by the ether-containingformulation by injecting a low salinity oil-immiscible formulationcomprising low salinity water having a salt content of at most 5 wt. %having a salt content of at most 5 wt. % into the formation, where thetotal salt content of the oil-immiscible formulation is at most 5 wt. %,and producing oil, an ether containing from 2 to 6 carbons, and waterfrom the formation. The art discloses injecting an oil-immiscibleformulation into a formation after the injection of a miscibleformulation into the formation, where the oil-immiscible formulation maycontain water and the miscible formulation may contain dimethyl ether.The salinity of the water is not limited therein, and, often, water usedin an EOR waterflood has a relatively high salinity—either because thewater used is seawater or because produced water is re-injected, whichhas the salinity of the formation. Low molecular weight ethers such asdimethyl ether, however, partition more readily into low salinity waterfrom the residual oil than into water having high salinity, therefore,more of a low-molecular weight ether may be recovered from residual oilusing the system and method of the present invention.

The system of the present invention provides a first well located abovean underground formation containing oil. The system also includes amechanism to inject a formulation comprising an ether containing from 2to 6 carbons into the formation, a mechanism for injecting anoil-immiscible formulation into the formation, where the oil-immiscibleformulation has a total salt content of at most 5 wt. % and compriseswater having a total salt content of at most 5 wt. %, and a mechanismfor producing oil, an ether containing from 2 to 6 carbons, and waterfrom the formation. At least one of the mechanisms for injecting theether-containing formulation into the formation, injecting theoil-immiscible formulation into the formation, and producing the oil,ether, and water from the formation is located at the first well.

In an embodiment of the system, the mechanisms for injecting theether-containing formulation into the formation, injecting theoil-immiscible formulation into the formation, and producing the oil,ether, and water from the formation are located at the first well. Inthis embodiment, the ether-containing formulation may be injected intothe formation for a period of time then, in a subsequent period of time,oil may be produced from the formation. Following production of oil fromthe formation after injection of the ether-containing formulation intothe formation, the oil-immiscible formulation may be injected into theformation for a period of time, after which oil, an ether, and water maybe produced from the formation.

In an embodiment of the system, the mechanism for injecting theether-containing formulation and the mechanism for injecting theoil-immiscible formulation into the formation may be the same mechanism.The ether-containing formulation and the oil-immiscible formulation maybe injected through the mechanism may be conducted sequentially orsimultaneously. If the ether-containing formulation and theoil-immiscible formulation are injected simultaneously, theether-containing formulation and the oil-immiscible formulation may bemixed together for co-injection through the mechanism for injecting theether-containing formulation and the oil-immiscible formulation.

In another embodiment of the system, the system may include a secondwell. The mechanism for injecting the ether-containing formulation intothe formation, the mechanism for injecting the oil-immiscibleformulation into the formation, and/or the mechanism for recovering oil,an ether, and water may be located at the second well. In thisembodiment, the ether-containing formulation may be injected into theformation at the first well for a period of time, followed by injectionof the oil-immiscible formulation into the formation at the first wellfor a period of time. Oil, an ether, and water may be produced at thesecond well. Alternatively, the ether-containing formulation may beinjected at the second well for a period of time followed by injectionof the oil-immiscible formulation at the second well for a period oftime, and oil, an ether, and water may be produced from the first well.Alternatively, the ether-containing formulation and the oil-immiscibleformulation may be injected simultaneously, preferably as a mixture, atthe first or second well, and oil, an ether, and water may be producedfrom the first or second well, where the oil, ether, and water areproduced from the first well if the ether-containing formulation andoil-immiscible formulation are injected at the second well or the oil,ether, and water may be produced from the second well if theether-containing formulation and oil-immiscible formulation are injectedat the first well. Alternatively, the ether-containing formulation maybe injected into the formation at the first well, and, after a timeperiod, the oil-immiscible formulation may be injected into theformation at the second well, and the oil, an ether, and water may beproduced at the first well, or the ether-containing formulation may beinjected into the formation at the second well, and, after a timeperiod, the oil-immiscible formulation may be injected into theformation at the first well, and the oil, an ether, and water may beproduced at the first well.

In another embodiment of the system, the system may include a thirdwell. The mechanism for injecting the ether-containing formulation intothe formation may be located at the first well, the mechanism forinjecting the oil-immiscible formulation may be located at the secondwell, and the mechanism for producing oil, an ether, and water may belocated at the third well. The ether-containing formulation may beinjected into the formation at the first well, the oil-immiscibleformulation may be injected into the second well, and oil, an ether, andwater may be recovered at the third well. The second well may be locatedrelative to the first and third wells in a position so that at least aportion of the oil-immiscible formulation drives the ether-containingformulation towards the third well for producing and so that at least aportion of ether trapped in residual oil in the formation partitionsinto the oil-immiscible formulation for recovery at the third well.

Referring now to FIG. 2 a, in some embodiments, an array of wells 200 isillustrated. Array 200 includes a first well, included in first wellgroup 202 (denoted by horizontal lines) and a second well, included insecond well group 204 (denoted by diagonal lines).

Each well in first well group 202 may be spaced a horizontal distanceand a vertical distance from adjacent wells in the first well group,where each horizontal distance between adjacent wells of the first wellgroup 202 may be roughly equal and the vertical distance betweenadjacent wells of the first well group 202 may be roughly equal. Eachwell in first well group 202 may have a horizontal distance 230 from anadjacent well in first well group 202. Each well in first well group 202may have a vertical distance 232 from an adjacent well in first wellgroup 202.

Each well in the second well group 204 may be spaced a horizontaldistance and a vertical distance from adjacent wells in the second wellgroup, where each horizontal distance between adjacent wells of thesecond well group may be roughly equal and each vertical distancebetween adjacent wells of the second well group may be roughly equal.Each well in second well group 204 may have a horizontal distance 236from an adjacent well in second well group 204. Each well in second wellgroup 204 may have a vertical distance 238 from an adjacent well insecond well group 204.

The wells of the first well group 202 have a distance from adjacentwells of the second well group 204. Each well in first well group 202may have a distance 234 from the adjacent wells in second well group204. Each well in second well group 204 may have a distance 234 from theadjacent wells in first well group 202.

In some embodiments, each well in first well group 202 is surrounded byfour wells in second well group 204. In some embodiments, each well insecond well group 204 is surrounded by four wells in first well group202.

In some embodiments, horizontal distance 230 is from about 5 to about1000 meters, or from about 10 to about 500 meters, or from about 20 toabout 250 meters, or from about 30 to about 200 meters, or from about 50to about 150 meters, or from about 90 to about 120 meters, or about 100meters.

In some embodiments, vertical distance 232 is from about 5 to about 1000meters, or from about 10 to about 500 meters, or from about 20 to about250 meters, or from about 30 to about 200 meters, or from about 50 toabout 150 meters, or from about 90 to about 120 meters, or about 100meters.

In some embodiments, horizontal distance 236 is from about 5 to about1000 meters, or from about 10 to about 500 meters, or from about 20 toabout 250 meters, or from about 30 to about 200 meters, or from about 50to about 150 meters, or from about 90 to about 120 meters, or about 100meters.

In some embodiments, vertical distance 238 is from about 5 to about 1000meters, or from about 10 to about 500 meters, or from about 20 to about250 meters, or from about 30 to about 200 meters, or from about 50 toabout 150 meters, or from about 90 to about 120 meters, or about 100meters.

In some embodiments, distance 234 is from about 5 to about 1000 meters,or from about 10 to about 500 meters, or from about 20 to about 250meters, or from about 30 to about 200 meters, or from about 50 to about150 meters, or from about 90 to about 120 meters, or about 100 meters.

In some embodiments, array of wells 200 may have from about 10 to about1000 wells, for example from about 5 to about 500 wells in first wellgroup 202, and from about 5 to about 500 wells in second well group 204.

In some embodiments, array of wells 200 is seen as a top view with firstwell group 202 and second well group 204 being vertical wells spaced ona piece of land. In some embodiments, array of wells 200 is seen as across-sectional side view with first well group 202 and second wellgroup 204 being horizontal wells spaced within a formation.

Referring now to FIG. 2 b, in some embodiments, array of wells 200 isillustrated. Array 200 includes a first well included in a first wellgroup 202 (denoted by horizontal lines) and a second well included in asecond well group 204 (denoted by diagonal lines).

In some embodiments, an ether-containing formulation is injected into anoil-containing underground formation through mechanisms located at thesecond wells of the second well group 204, then, after injecting theether-containing formulation into the formation or simultaneously withthe injection of the ether-containing formulation, an oil-immiscibleformulation having a salt content of at most 5 wt. % and containingwater having a salt content of at most 5 wt. % is injected into theformation through mechanisms located at the second wells of the secondwell group 204, and oil, an ether, and water are produced from theformation through mechanisms located at the first wells of the firstwell group 202. The mechanisms for injecting the ether-containingformulation and the mechanisms for injecting the oil-immiscibleformulation located at the second wells may be the same mechanisms. Asillustrated, the ether-containing formulation and the oil-immiscibleformulation have injection profile 208, and oil recovery profile 206 isbeing produced to first well group 202.

In some embodiments, an ether-containing formulation is injected into anoil-containing underground formation through mechanisms in the firstwells of the first well group 202, then, after injecting theether-containing formulation into the formation or simultaneously withinjection of the ether-containing formulation, an oil-immiscibleformulation having a salt content of at most 5 wt. % and containingwater having a salt content of at most 5 wt. % is injected into theformation through mechanisms in the first wells of the first well group202, and oil, an ether, and water are produced from the formationthrough mechanisms in the second wells of the second well group 204. Themechanisms for injecting the ether-containing formulation and theoil-immiscible formulation located at the first wells may be the same.As illustrated, the ether-containing formulation and the oil-immiscibleformulation have injection profile 206, and oil recovery profile 208 isbeing produced to second well group 204.

In some embodiments, first well group 202 may be used for injecting anether-containing formulation followed by an oil-immiscible formulationhaving a salt content of at most 5 wt. % and comprised of water having asalt content of at most 5 wt. %, and second well group 204 may be usedfor producing oil from the formation for a first time period; thensecond well group 204 may be used for injecting an ether-containingformulation followed by an oil-immiscible formulation having a saltcontent of at most 5 wt. % comprising water having a salt content of atmost 5 wt. %, and first well group 202 may be used for producing oilfrom the formation for a second time period, where the first and secondtime periods comprise an injection cycle.

The ether-containing formulation may be injected for the first timeperiod, and an oil-immiscible formulation having a salt content of atmost 5 wt. % comprising water having a salt content of at most 5 wt. %may be injected for the second time period. In some embodiments, thefirst time period may be the first 10% to about 80% of the injectioncycle, or the first 20% to about 60% of the injection cycle, the first25% to about 40% of the injection cycle, and the second time period maybe the remainder of the injection cycle.

Alternatively, the ether-containing formulation and the oil-immiscibleformulation having a salt content of at most 5 wt. % comprising waterhaving a salt content of at most 5 wt. % may be injected into theoil-containing formation together. The ether-containing formulation andthe oil-immiscible formulation may be mixed on the surface above theoil-containing formulation and then injected together into theoil-containing formation. The ether-containing formulation and theoil-immiscible formulation may be injected separately at the surfaceabove the oil-containing formation and mixed in the well prior to beinginjected into the oil-containing formation, or the ether-containingformulation and the oil-immiscible formulation may be injectedseparately at the surface above the oil-containing formation and mixedupon entering the formation.

Referring now to FIG. 2 c, in some embodiments, array of wells 200 isillustrated. Array 200 includes first wells included in a first wellgroup 202 (denoted by horizontal lines) and second wells included in asecond well group 204 (denoted by diagonal lines).

In some embodiments, an ether-containing formulation followed by orsimultaneously with an oil-immiscible formulation having a salt contentof at most 5 wt. % comprising water having a salt content of at most 5wt. % is injected into the formation at second wells of second wellgroup 204, and oil, an ether, and water are produced from the formationat first wells of the first well group 202. As illustrated, theether-containing formulation and immiscible water formulation haveinjection profile 208 with overlap 210 with oil recovery profile 206,which is being produced to first well group 202.

In some embodiments, an ether-containing formulation followed by orsimultaneously with an oil-immiscible formulation having a salt contentof at most 5 wt. % comprising water having a salt content of at most 5wt. % is injected into the formation at first wells of first well group202, and oil, an ether, and water are produced from second wells of thesecond well group 204. As illustrated, the ether-containing formulationand oil-immiscible formulation have injection profile 206 with overlap210 with oil recovery profile 208, which is being produced to secondwell group 204.

In some embodiments, an ether-containing formulation and anoil-immicsible formulation having a salt content of at most 5 wt. %comprising water having a salt content of at most 5 wt. % may beinjected together into the formation at first wells of the first wellgroup 202 and oil, ether, and water may be produced from the formationat second wells of the second well group 204. Alternatively, anether-containing formulation and an oil-immiscible formulation having asalt content of at most 5 wt. % comprising water having a salt contentof at most 5 wt. % may be injected together into an oil-bearingformation at second wells of the second well group 204 and oil, ether,and water may be produced at first wells of the first well group 202.

Referring now to FIG. 2 d, in some embodiments, array of wells 200 isillustrated. Array 200 includes first wells in a first well group 202(denoted by horizontal lines), second wells in a second well group 204(denoted by diagonal lines), and third wells in a third well group 212(denoted by vertical lines).

Each well in first well group 202 may be spaced a horizontal distanceand a vertical distance from adjacent wells in the first well group,where each horizontal distance between adjacent wells of the first wellgroup 202 may be roughly equal and the vertical distance betweenadjacent wells of the first well group 202 may be roughly equal. Eachwell in first well group 202 may have a horizontal distance 230 from anadjacent well in first well group 202. Each well in first well group 202may have a vertical distance 232 from an adjacent well in first wellgroup 202.

Each well in the second well group 204 may be spaced a horizontaldistance and a vertical distance from adjacent wells in the second wellgroup, where each horizontal distance between adjacent wells of thesecond well group may be roughly equal and each vertical distancebetween adjacent wells of the second well group may be roughly equal.Each well in second well group 204 may have a horizontal distance 236from an adjacent well in second well group 204. Each well in second wellgroup 204 may have a vertical distance 238 from an adjacent well insecond well group 204.

Each well in the third well group 212 may be spaced a horizontaldistance and a vertical distance from adjacent wells in the third wellgroup, where each horizontal distance between adjacent wells of thethird well group may be roughly equal and each vertical distance betweenadjacent wells of the third well group may be roughly equal. Each wellin third well group 212 may have a horizontal distance 240 from anadjacent well in third well group 212. Each well in third well group 212may have a vertical distance 242 from an adjacent well in second wellgroup 204.

The wells of the first well group 202 may have a distance from adjacentwells of the second well group 204. Each well in first well group 202may have a distance 234 from an adjacent well in second well group 204.Each well in second well group 204 may have a distance 234 from anadjacent well in first well group 202. The wells of the second wellgroup 204 may have a distance from adjacent wells of the third wellgroup 212. Each well in the second well group 204 may have a distance244 from an adjacent well in the third well group 212. Each well in thethird well group 212 may have a distance 244 from an adjacent well inthe second well group 204. The wells of the first well group 202 mayhave a distance from adjacent wells of the third well group. Each wellin the first well group 202 may have a distance 244 from an adjacentwell in the third well group 212. Each well in the third well group mayhave a distance 244 from an adjacent well in the first well group 202.

As shown in FIG. 2 d, in some embodiments, each well in first well group202 is surrounded by four wells in second well group 204. The four wellsin the second well group may be, in turn, surrounded by eight wells ofthe third well group 212. In this embodiment, mechanisms for producingoil, an ether, and water from the formation may be located at the wellsof the first well group 202, mechanisms for injecting theether-containing formulation into the formation may be located at thewells of the second well group 204, and mechanisms for injecting theoil-immiscible formulation having a salt content of at most 5 wt. %comprising water having a salt content of at most 5 wt. % into theformation may be located at wells of the third well group 212. Theether-containing formulation may be injected into the formation at thewells of the second well group 204 and the oil-immiscible formulationmay be injected into the formation at the wells of the third well group212, where the ether-containing formulation mobilizes oil for productionat the wells of the first well group 202 and the oil-immiscibleformulation drives the ether-containing formulation and the ethermobilized oil for production at the wells of the first well group whilerecovering an ether from residual oil for production at the wells of thefirst well group 202 along with a portion of the oil-immiscibleformulation.

In some embodiments, horizontal distance 230 is from 5 to 1000 meters,or from 10 to 500 meters, or from 20 to 250 meters, or from 30 to 200meters, or from 50 to 150 meters, or from 90 to 120 meters, or 100meters.

In some embodiments, vertical distance 232 is from 5 to 1000 meters, orfrom 10 to 500 meters, or from 20 to 250 meters, or from 30 to 200meters, or from 50 to 150 meters, or from 90 to 120 meters, or 100meters.

In some embodiments, horizontal distance 236 is from 5 to 1000 meters,or from 10 to 500 meters, or from 20 to 250 meters, or from 30 to 200meters, or from 50 to 150 meters, or from 90 to 120 meters, or 100meters.

In some embodiments, vertical distance 238 is from 5 to 1000 meters, orfrom 10 to 500 meters, or from 20 to 250 meters, or from 30 to 200meters, or from 50 to 150 meters, or from 90 to 120 meters, or 100meters.

In some embodiments, horizontal distance 240 is from 5 to 1000 meters,or from 10 to 500 meters, or from 20 to 250 meters, or from 30 to 200meters, or from 50 to 150 meters, or from 90 to 120 meters, or 100meters.

In some embodiments, vertical distance 242 is from 5 to 1000 meters, orfrom 10 to 500 meters, or from 20 to 250 meters, or from 30 to 200meters, or from 50 to 150 meters, or from 90 to 120 meters, or 100meters.

In some embodiments, distance 234 is from 5 to 1000 meters, or from 10to 500 meters, or from 20 to 250 meters, or from 30 to 200 meters, orfrom 50 to 150 meters, or from 90 to 120 meters, or 100 meters. In someembodiments, distance 244 is from 5 to 1000 meters, or from 10 to 500meters, or from 20 to 250 meters, or from 30 to 200 meters, or from 50to 150 meters, or from 90 to 120 meters, or 100 meters. In someembodiments, distance 246 is greater than distance 244 and is from 5 to1000 meters, or from 10 to 500 meters, or from 20 to 250 meters, or from30 to 200 meters, or from 50 to 150 meters, or from 90 to 120 meters, or100 meters.

In some embodiments, array of wells 200 may have from 10 to 1500 wells,for example from 5 to 500 wells in first well group 202, and from 5 to500 wells in second well group 204, and from 5 to 500 wells in thirdgroup 212.

In some embodiments, array of wells 200 is seen as a top view with firstwell group 202, second well group 204, and third well group 212 beingvertical wells spaced on a piece of land. In some embodiments, array ofwells 200 is seen as a cross-sectional side view with first well group202, second well group 204, and third well group 212 being horizontalwells spaced within a formation.

In an embodiment, an ether-containing formulation may be injected intothe formation at second wells of the second well group 204. Anoil-immiscible formulation having a salt content of at most 5 wt. %comprising water having a salt content of at most 5 wt. % may beinjected into the formation at third wells of the third well group 212while the ether-containing formulation is injected into the formation orafter the ether-containing formulation is injected into the formation.Oil, an ether, and water may be produced from the formation at firstwells of the first well group 202. As illustrated, the oil-immiscibleformulation has an injection profile 214 that may overlap with theether-containing formulation injection profile 208, and theether-containing formulation injection profile may overlap with the oilrecovery profile 206. Preferably, the oil-immiscible formulationinjection profile 208 may overlap both the DME formulation injectionprofile 208 and the oil recovery profile 206.

The system of the present invention may include a mechanism forproducing an ether-containing formulation. The mechanism for producingan ether-containing formulation may convert a hydrocarbon into an etherhaving from 2 to 6 carbons by any known method for effecting such aconversion as known in the art. For example, a dimethyl etherformulation may be produced by a mechanism for converting a hydrocarboninto DME by any known method for conversion of a hydrocarbon into DME.In an embodiment, a mechanism for producing a dimethyl ether formulationmay convert natural gas separated from the formation into synthesis gas,generate methanol from the synthesis gas, and produce the dimethyl etherformulation from the methanol. U.S. Pat. Nos. 7,168,265; 7,100,692; and7,083,662 disclose suitable methods for production of dimethyl etherfrom natural gas that may be utilized by the mechanism for producing thedimethyl ether formulation.

The mechanism for producing the ether-containing formulation may mix anether containing from 2 to 6 carbons with one or more oil-miscibleenhanced oil recovery agents to produce the ether-containingformulation. The one or more oil-miscible enhanced oil recovery agentsthat may be mixed with the ether to produce an ether-containingformulation may include methanol, carbon dioxide, C₁-C₆ hydrocarbons,nitrogen, naphtha solvent, asphalt solvent, kerosene, xylene,trichloroethane, and mixtures thereof.

The mechanism for producing the ether-containing formulation may includea mechanism for heating the ether-containing formulation to lower theviscosity of fluids in the formation. Conventional heating mechanismsmay be used to heat the ether-containing formulation prior to injectingthe ether-containing formulation into the formation.

The mechanism for producing the ether-containing formulation ispreferably located at the same well where a mechanism for injecting theether-containing formulation into the formation is located. For example,if a mechanism for injecting the ether-containing formulation into theformation is located at a well of the first well group 202 the mechanismfor producing the ether-containing formulation may be located at thesame well of the first well group 202.

The system of the present invention may include a mechanism forseparating a mixture of an ether comprising from 2 to 6 carbons andwater from oil produced by the mechanism for producing oil from theformation. The mechanism for separating a mixture of the ether and waterfrom oil is preferably located at a well of the well group where amechanism for producing oil from the formation is located. The mechanismfor producing oil from the formation may produce the ether and water inaddition to oil, where the ether and water may be separated from the oilproduced from the formation by the mechanism for separating the etherand water from oil.

The mechanism for separating a mixture of an ether comprising from 2 to6 carbons and water from oil produced from the formation may include agas liquid separator for separating a gas-ether mixture from producedoil, a liquid portion of the ether, and water, a liquid-liquid separatorfor separating an oil liquid phase from an ether/water phase, and/or ascrubber for separating the ether from gas by washing the gas withwater.

The system of the present invention may include a mechanism forproviding an oil-immiscible formulation having a salt content of at most5 wt. % that is comprised of water having a salt content of at most 5wt. %. The mechanism for providing the oil-immiscible formulation may belocated at one or more wells where a mechanism for injecting theoil-immiscible formulation is located. The mechanism for providing anoil-immiscible formulation may comprise a water source and a mechanismfor removing salts from the water source. The mechanism for removingsalts from the water source may be a conventional mechanism fordesalting water, for example, a nanofiltration system utilizing one ormore nanofiltration membranes, a reverse osmosis system utilizing one ormore reverse osmosis membranes, a combination of nanofiltration andreverse osmosis membranes, or a distillation column for distillingwater.

In the method of the present invention, an ether-containing formulationcomprising an ether comprised of from 2 to 6 carbon atoms is injectedinto a formation containing oil, for example, an underground formationcontaining oil. The ether-containing formulation may be contacted withthe oil in the formation to mobilize oil in the formation, where themobilized oil may be produced from the formation. Mobilizing the oilleaves an oil residuum in the formation that contains a portion of theether of the ether-containing formulation. An oil-immiscible formulationis injected into the formation, where the oil-immiscible formulation hasa salt content of at most 5 wt. % and comprises water having a saltcontent of at most 5 wt. %. The oil-immiscible formulation may drive themobilized oil and ether-containing formulation across the formation forproduction, and separates a portion of the ether from the oil residuuminto the oil-immiscible formulation by partitioning from the oilresiduum into the water. Oil, the ether, and water are produced from theformation, where the oil may include the mobilized oil and the ether mayinclude ether separated from the oil residuum by the oil-immiscibleformulation.

Injecting the ether-containing formulation into the formation containingoil may be accomplished by any known method for injecting a liquidand/or a gas into a formation, depending on the state of theether-containing formulation. One suitable method is injecting theether-containing formulation into the formation through a conduit in afirst well, allowing the ether-containing formulation to soak in theformation to mobilize oil therein, and then producing at least a portionof the mobilized oil and at least a portion of the ether by pumping themobilized oil and the ether out of the formation through a conduit inthe first well. Another suitable method is injecting theether-containing formulation into the formation through a conduit in afirst well, allowing the ether-containing formulation to mobilize oil inthe formation, and producing at least a portion of the mobilized oil andat least a portion of the ether by pumping the mobilized oil and etherout of the formation through a conduit in a second well. The selectionof the method used to inject the ether-containing formulation into theformation is not critical.

The amount of the ether-containing formulation injected into theformation may be an amount sufficient to mobilize oil in the formationfor production from the formation. The amount of the ether-containingformulation injected into the formation may be from 0.05 to 0.75 of theformation pore volume, or from 0.1 to 0.5, or from 0.15 to 0.3 of theformation pore volume. The amount of the ether-containing formulationinjected into the formation may be selected to be an amount sufficientto increase the mobility of the oil in the formation. The amount of theether-containing formulation injected into the formation may be anamount selected to be sufficient to reduce the viscosity of the oil inthe formation relative to the viscosity of the oil in the formationprior to injection of the ether-containing formulation into theformation. The amount of the ether-containing formulation injected intothe formation may be selected to be an amount effective to reduce thebubble point of the oil in the formation.

The ether-containing formulation may be injected into the formation at apressure greater than the formation pressure as measured immediatelyprior to injecting the ether-containing formulation into the formation.The ether-containing formulation may be injected into a formation at apressure up to the fracture pressure of the formation. In someembodiments, the ether-containing formulation may be injected into theformation below the fracture pressure of the formation, for example fromabout 40% to about 90% of the fracture pressure of the formation. Theether-containing formulation may be injected into the formation at apressure of from above 0 to 37,000 kilopascals above the formationpressure as measured immediately prior to injecting the ether-containingformulation into the formation.

The ether-containing formulation may be heated to lower the viscosity offluids in the formation. The ether-containing formulation may be heatedto a temperature of from 40° C. to 275° C., or from 50° C. to 200° C.,or from 75° C. to 150° C. The ether-containing formulation may be heatedprior to being injected into the formation to lower the viscosity offluids in the formation, for example heavy oils, paraffins, asphaltenes,etc. The ether-containing formulation may also be heated and/or boiledwhile within the formation by the use of a heated fluid or a heater tolower the viscosity of fluids in the formation. In some embodiments,heated water and/or steam may be used to heat and/or vaporize theether-containing formulation in the formation. In some embodiments, theether-containing formulation may be heated and/or boiled while withinthe formation with a heater. One suitable heater is disclosed inCanadian Patent No. 2503394.

The ether-containing formulation may be mixed in with oil in theformation to form a mixture which may be produced from the formationthrough a well. Mixing the ether-containing formulation with the oil inthe formation may mobilize previously immobilized oil, where themobilized oil/ether-containing formulation mixture is mobile in theformation and may move through the formation to a well from which themixture may be produced from the formation, thereby enabling thepreviously immobilized oil to be produced from the formation.Mobilization and movement of previously immobilized oil through theformation by mixing the ether-containing formulation and the oil mayleave residual oil in the formation. A portion of the ether from theether-containing formulation may remain with the residual oil in theformation.

Injecting the oil-immiscible formulation into the formation may beaccomplished by any known method for injecting a liquid and/or a gasinto a formation, depending on the state of the oil-immiscibleformulation. The oil-immiscible formulation may be injected into theformation after the ether-containing formulation is injected into theformation. In one embodiment, in a first time period theether-containing formulation may be injected into the formation at afirst well and allowed to soak in the formation to mobilize oil in theformation, and subsequently oil, and ether may be produced from thefirst well. Then, in a second time period subsequent to the first timeperiod, the oil-immiscible formulation may be injected into theformation at the first well and allowed to soak in the formation torecover the ether from residual oil, and subsequently oil, ether, andwater may be produced from the first well. In another embodiment, in afirst time period the ether-containing formulation may be injected intoa formation at a first well. Subsequently, in a second time period, theoil-immiscible formulation may be injected into the formation at thefirst well. Oil, ether, and water may be produced from the formation ata second well over the first and second time periods. Theether-containing formulation may be injected at the first well tomobilize oil in the formation to be driven for production at the secondwell. The oil-immiscible formulation may be injected at the first wellto drive the mixture of the ether-containing formulation and mobilizedoil through the formation for production at the second well. Theoil-immiscible formulation may move through the formation from the firstwell to the second well and recover ether from residual oil in theformation for production at the second well. In another embodiment, theether-containing formulation and the oil-immiscible formulation having asalt content of at most 5 wt. % comprising water having a salt contentof at most 5 wt. % may be injected together into the oil-bearingformation at a first well and oil, ether, and water may be produced fromthe formation at a second well. Alternatively, the ether-containingformulation and the oil-immiscible formulation having a salt content ofat most 5 wt. % comprising water having a salt content of at most 5 wt.% may be injected together into the oil-bearing formation at a secondwell and oil, ether, and water may be produced from the formation at afirst well.

In another embodiment, the ether-containing formulation may be injectedinto a formation at a first well. Oil, ether, and water may be producedfrom the formation at a second well. The oil-immiscible formulation maybe injected into the formation at a third well. The first, second, andthird wells may be positioned in the formation so the ether-containingformulation mobilizes oil in the formation for production at the secondwell and the oil-immiscible formulation drives the ether-containingformulation and the mobilized oil through the formation for productionat the second well, where the oil-immiscible formulation recovers etherfrom residual oil in the formation and may move through the formationfor production of the recovered ether and water at the second well. Theether-containing formulation and the oil-immiscible formulation may beinjected over the same time period from the first and third wells,respectively, or the ether-containing formulation may be injected intothe formation at the first well for a first time period and theoil-immiscible formulation may be injected into the formation at thethird well for a second time period, where the start of the second timeperiod is subsequent to the start of the first time period. The amountof the oil-immiscible formulation injected into the formation may be anamount sufficient to drive a mixture of the ether-containing formulationand mobilized oil through the formation for production from theformation and/or to recover at least a portion of the ether fromresidual oil in the formation for production from the formation. Theamount of the ether-containing formulation injected into the formationmay be from 0.05 to 0.75 of the formation pore volume, or from 0.1 to0.5, or from 0.15 to 0.3 of the formation pore volume or the amount ofthe ether-containing formulation may be at least equal the formationpore volume, or may be from 1 to 2.5 times, or from 1.1 to 2.0 times, orfrom 1.2 to 1.5 times the formation pore volume. The volume ratio of theamount of the oil-immiscible formulation injected into the formation tothe amount of the ether-containing formulation injected into theformation may be from 1.3:1.0 to 50:1, or from 3:1 to 15:1.

The oil-immiscible formulation may be injected into the formation at apressure greater than the formation pressure as measured immediatelyprior to injecting the oil-immiscible formulation into the formation.The oil-immiscible formulation may be injected into a formation at apressure up to the fracture pressure of the formation. Theoil-immiscible formulation may be injected into the formation at apressure of from above 0 to 37,000 kilopascals above the formationpressure as measured immediately prior to injecting the oil-immiscibleformulation into the formation.

The oil-immiscible formulation may be heated. The oil-immiscibleformulation may be heated to a temperature of from 40° C. to 275° C., orfrom 50° C. to 200° C., or from 75° C. to 150° C. The oil-immiscibleformulation may be heated prior to being injected into the formation.The oil-immiscible formulation may also be heated while within theformation by the use of a heated fluid or a heater.

Production of oil and the ether from the formation may be accomplishedby any known method. Suitable methods include subsea production, surfaceproduction, secondary, or tertiary production. The selection of themethod used to produce the oil and ether from the underground formationis not critical.

Referring now to FIGS. 3 a and 3 b, in some embodiments of theinvention, system 300 is illustrated. System 300 includes undergroundformation 302, underground formation 304, underground formation 306, andunderground formation 308. Facility 310 is provided at the surface. Well312 traverses formations 302 and 304, and has openings in formation 306.Portions 314 of formation 306 may be optionally fractured and/orperforated. During primary production, oil and gas from formation 306 isproduced into portions 314, into well 312, and travels up to facility310. Facility 310 then separates gas, which is sent to gas processing316, and liquid, which is sent to liquid storage 318. Facility 310 alsoincludes ether-containing formulation storage 330 and oil-immiscibleformulation storage 332. As shown in FIG. 3 a, the ether-containingformulation may be pumped down well 312 that is shown by the down arrowand pumped into formation 306. In an embodiment of the method of thepresent invention, the ether-containing formulation may be injected intothe formation through well 312 to mobilize and drive oil in theformation to a production well for production from the formation. Theoil-immiscible formulation having a salt content of at most 5 wt. %comprising water having a salt content of at most 5 wt. % may then beinjected into the formation through well 312 immediately aftercompletion of injection of the ether-containing formulation into theformation to recover ether from residual oil and to drive oil and etherin the formation to a production well for production from the formation.

Alternatively, the ether-containing formulation may be left to soak information 306 for a period of time from about 1 hour to about 15 days,for example from about 5 to about 50 hours. During the soak period, theether-containing formulation may mix with and mobilize oil in theformation 306. After the soaking period, as shown in FIG. 3 b, a mixtureof the mobilized oil and the ether-containing formulation may then beproduced back up well 312 to facility 310 as shown by the up arrow.After producing the mixture of mobilized oil and the ether-containingformulation, as shown in FIG. 3 a, the oil-immiscible formulation may bepumped down well 312 as shown by the down arrow and pumped intoformation. The oil-immiscible formulation may be left to soak information 306 for a period of time from about 1 hour to about 15 days,for example from about 5 to about 50 hours. During the soak period theoil-immiscible formulation may contact residual oil in formation 306 andextract ether from the residual oil. After the soaking period, as shownin FIG. 3 b, the oil-immiscible formulation along with any etherextracted from the residual oil is then produced back up well 312 tofacility 310 as shown by the up arrow.

Alternatively, the ether-containing formulation and the oil-immiscibleformulation may be injected together into the formation through well 312to drive oil and ether to the production well for production from theformation.

Facility 310 is adapted to separate oil from the ether and waterrecovered from the formation. Separation may be effected by facility310, for example, by phase separation, washing, scrubbing, ordistillation. The separated ether and water may be re-injected into theformation as a portion of the ether-containing formulation byre-injection into well 312.

In some embodiments, well 312 as shown in FIG. 3 a injecting intoformation 306 may be representative of a well in well group 202, andwell 312 as shown in FIG. 3 b producing from formation 306 may berepresentative of a well in well group 204.

In some embodiments, well 312 as shown in FIG. 3 a injecting intoformation 306 may be representative of a well in well group 204, andwell 312 as shown in FIG. 3 b producing from formation 306 may berepresentative of a well in well group 202.

Referring now to FIG. 3 c, in some embodiments of the invention, system400 is illustrated. System 400 includes underground formation 402,formation 404, formation 406, and formation 408. Production facility 410is provided at the surface. Well 412 traverses formation 402 and 404 hasopenings at formation 406. Portions of formation 414 may be optionallyfractured and/or perforated. As oil is produced from formation 406 itenters portions 414, and travels up well 412 to production facility 410.Gas and liquid may be separated, and gas may be sent to gas storage 416,and liquid may be sent to liquid storage 418. Production facility 410 isable to produce and/or store an ether-containing formulation, which maybe produced and stored in production/storage 430. Dimethyl ether,diethyl ether, and/or other ethers from well 412 may be sent toether-containing formulation production/storage 430. Facility 410 alsois able to produce and/or store an oil-immiscible formulation, which maybe produced and/or stored in production/storage 440.

An ether-containing formulation is injected into formation 406 bypumping the ether-containing formulation down well 432 to portions 434of formation 406. The ether-containing formulation traverses formation406 to aid in the production of oil by mobilizing oil in formation 406for production at well 412, and then the ether-containing formulationand oil may be produced at well 412 to production facility 410. Theether-containing formulation may then be recycled, for example byseparating the ether-containing formulation from the oil by phaseseparation, or distilling or flashing the mixture of oil and ethercontaining formulation then re-injecting the ether-containingformulation into well 432.

After injection of the ether-containing formulation into the formation406 down well 432, or together with the ether-containing formulation,the oil-immiscible formulation is injected into formation 406 by pumpingthe oil-immiscible formulation down well 432. The oil-immiscibleformulation traverses formation 406 to drive the mixture of theether-containing formulation and the mobilized oil for production atwell 412. The oil-immiscible formulation extracts ether left in residualoil by the passage of the ether-containing formulation through theformation, and the mixture of the oil-immiscible formulation and etherextracted from residual oil are produced at production well 412.

In some embodiments, well 412 which is producing oil is representativeof a well in well group 202, and well 432 which is being used to injectthe ether-containing formulation and the oil-immiscible formulation isrepresentative of a well in well group 204.

In some embodiments, well 412 which is producing oil is representativeof a well in well group 204, and well 432 which is being used to injectthe ether-containing formulation and the oil-immiscible formulation isrepresentative of a well in well group 202.

Referring now to FIG. 3 d, in some embodiments of the invention, system500 is illustrated. System 500 includes underground formation 502,formation 504, formation 506, and formation 508. Production facility 510is provided at the surface. Well 512 traverses formation 502 and 504 hasopenings at formation 506. Portions of formation 514 may be optionallyfractured and/or perforated. As oil is produced from formation 506 itenters portions 514, and travels up well 512 to production facility 510.Gas and liquid may be separated, and gas may be sent to gas storage 516,and liquid may be sent to liquid storage 518. Production facility 510 isable to produce and/or store an ether-containing formulation, which maybe produced and stored in production/storage 530. Dimethyl ether,diethyl ether, and/or other ethers from well 512 may be sent toether-containing formulation production/storage 530. Facility 510 alsois able to produce and/or store an oil-immiscible formulation, which maybe produced and/or stored in production/storage 540.

An ether-containing formulation is injected into formation 506 bypumping the ether-containing formulation down well 532 to portions 534of formation 506. The ether-containing formulation traverses formation506 to aid in the production of oil by mobilizing oil in formation 506for production at well 512, and then the ether-containing formulationand oil may be produced at well 512 to production facility 510. Theether-containing formulation may then be recycled, for example byseparating the ether-containing formulation from the oil by phaseseparation, or distilling or flashing the mixture of oil and ethercontaining formulation then re-injecting the ether-containingformulation into well 532.

After initial injection of the ether-containing formulation into theformation 506 down well 532, the oil-immiscible formulation is injectedinto formation 506 by pumping the oil-immiscible formulation down well542 to portions 544 of formation 506. The oil-immiscible formulationtraverses formation 506 to drive the mixture of the ether-containingformulation and the mobilized oil for production at well 512. Theoil-immiscible formulation extracts ether left in residual oil by thepassage of the ether-containing formulation through the formation, andthe mixture of the oil-immiscible formulation and ether extracted fromresidual oil are produced at production well 512.

In some embodiments, well 512 which is producing oil is representativeof a well in well group 202, and well 532 which is being used to injectthe ether-containing formulation is representative of a well in wellgroup 204 and well 542 which is being used to inject the oil-immiscibleformulation is representative of a well in well group 212.

In some embodiments, ether from the ether-containing formulation isproduced from the formation with oil. In some embodiments, water fromthe oil-immiscible formulation is produced from the formation with oiland the ether from the ether-containing formulation.

In some embodiments, oil produced may be transported to a refineryand/or a treatment facility. The oil may be processed to producecommercial products such as transportation fuels including gasoline anddiesel, heating fuel, lubricants, chemicals, and/or polymers. Processingmay include distilling and/or fractionally distilling the oil to produceone or more distillate fractions. In some embodiments, the oil, and/orthe one or more distillate fractions may be subjected to a process ofone or more of the following: catalytic cracking, hydrocracking,hydrotreating, coking, thermal cracking, distilling, reforming,polymerization, isomerization, alkylation, blending, and dewaxing.

The ether-containing formulation utilized in the system and method ofthe present invention comprises an ether containing from 2 to 6 carbonatoms. The ether-containing formulation may comprise one or more ethersselected from the group consisting of dimethyl ether, diethyl ether,methyl tertiary butyl ether, ethyl tertiary butyl ether, tertiary amylmethyl ether, methyl ethyl ether, dimethoxymethane, andpolydimethoxymethane. The ether-containing formulation may comprise from5 to 100 wt. % of the one or more ethers, or may comprise from 10-95 wt.%, or from 25-90 wt. %, or from 40-85 wt. %, or at least 50 wt. %, or atleast 75 wt. %, or at least 80 wt. %, or at least 90 wt. %, or at least95 wt. %, or at least 97 wt. %, or 100 wt. % of the one or more ethers.In an embodiment, the ether-containing formulation may comprise from 5to 100 wt. %, or from 10-95 wt. %, or from 25-90 wt. %, or from 40-85wt. %, or at least 50 wt. %, or at least 75 wt. %, or at least 80 wt. %,or at least 90 wt. %, or at least 95 wt. %, or at least 97 wt., or 100wt. % dimethyl ether.

The ether-containing formulation may contain other non-ether components.The ether containing-formulation may contain water, nitrogen, carbondioxide, carbon monoxide, hydrogen sulfide, and hydrocarbons other thanethers including: glycols such as mono-ethylene glycol, di-ethyleneglycol, tri-ethylene glycol, and tetra-ethylene glycol; ethanol,methanol, or other alcohols, acetals, polyols, methyl isobutyl carbinol,butyl propionate, methyl acetate, ethyl acetate, tertiary butyl acetate,or other esters, methyl ethyl ketone, methyl isobutyl ketone, acetone,or other ketones, dimethyl carbonate, diethyl carbonate, octane,pentane, LPG, C₂-C₆ aliphatic hydrocarbons, diesel, mineral spirits,naphtha solvent, asphalt solvent, kerosene, xylene, and/ortrichloroethane. Any water in the ether-containing formulation may havea salt content that is at least 1 wt. %, or at least 2 wt. %, or atleast 5 wt. %, or at least 10 wt. % greater than the salt content of theoil-immiscible formulation.

The oil-immiscible formulation used in the system and method of thepresent invention has a salt content of at most 5 wt. % and is comprisedof water having a salt content of at most 5 wt. %. The oil-immiscibleformulation may comprise at least 80 wt. %, or at least 90 wt. %, or atleast 95 wt. %, or at least 97 wt. % water having a salt content of atmost 5 wt. %. In an embodiment, the oil-immiscible formulation consistsof water having a salt content of at most 5 wt. %. The water of theoil-immiscible formulation has a salt content of at most 5 wt. %, andmay have a salt content of at most 3 wt. %, or at most 2 wt. %, or atmost 1 wt. %. The water of the oil-immiscible formulation may be in gasor liquid form. The oil-immiscible formulation may include suitableoil-immiscible components mixed with the water of the oil-immiscibleformulation including air and/or nitrogen.

To facilitate a better understanding of the present invention, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, thescope of the invention. The scope of the invention is to be defined bythe claims appended hereto.

Example

Experiments were conducted to determine the impact of salt on thesolubility of DME in water. The solubility of DME in brines of 3, 10,and 20 wt % NaCl and in fresh water (0 wt. % NaCl) were measured atpressures of 3.4 MPa (500 psi), 6.9 MPa (1000 psi), and 10.3 MPa (1500psi) along 20° C. and 50° C. isotherms. The solubility of DME in 10 wt.% NaCl was measured at pressures of 3447 KPa (500 psia), 6895 KPa (1000psia), and 10342 KPa (1500 psia) for use as a basis for validation ofextrapolation to higher temperatures. The experimental protocol issummarized in Table 1.

TABLE 1 T [° C.] P [psia] 30 50 80 120 1500 3, 10, 20 wt. % NaCl 10 wt.% NaCl LLE, Subsurface PVT 1000 500 4 pressure points between P^(VAP)and P^(VLLE) VLE and VLLE, Surface Facilities

Vapor-liquid equilibrium (VLE) data were measured as a first step of theliquid-liquid equilibrium measurements. A weighed brine solution wasadded to an autoclave and warmed to the selected temperature withstirring. After the brine solution reached thermal equilibrium, vaporwas withdrawn from the autoclave into a weighed trap to remove lightgases such as nitrogen or carbon dioxide. After the solution returned totemperature, the pressure was measured by a pressure transducer. Thetemperature and pressure were logged at ten second intervals bycomputer.

Aliquots of a measured volume of degassed dimethyl ether (DME) were thenadded to the autoclave from the pump. After the pressure and temperaturestabilized, the pressure was measured. Aliquots of DME were then addedto the brine mixture until a second liquid phase formed (the pressure nolonger changes upon addition of DME). The pressure at this condition wasalso measured.

The data to this point consisted of masses of brine and DME (calculatedfrom the volume) added to the autoclave and the resulting equilibriumpressure. These values, along with the cell volume, temperature, andcritical properties of water and DME, were used to derive equilibriumliquid and vapor compositions by using a flash algorithm and an activitycoefficient equation. A non-random two liquid equation was selected tomodel the liquid phase non-idealities. Liquid densities required by theflash routine were measured or taken from published brine densities, andvapor densities were calculated from the Peng-Robinson equation ofstate.

Once a second liquid phase rich in DME was present, the stirrer wasturned off and the contents of the autoclave were allowed to settle.Then aliquots of the lower liquid phase were slowly drawn into a weighedsample receiver. This sample receiver was connected to an empty, weighedgas bag. During sampling, most of the DME in the sample flashed out ofthe brine sample and flowed into the gas bag. The brine mixture in thesample receiver was stirred by an explosion-proof magnetic stirrer tohelp the DME flash out. The receiver was also thermostatted at 30° C. toprovide a consistent condition for the final state of the samples.

After the sample was taken, the receiver and gas bag were allowed toequilibrate for ten to twenty minutes. Then the sample receiver and gasbag were both weighed. The buoyant effect of the atmosphere on the gasbag was included to determine the actual mass of DME collected in thebag.

The amount of DME still dissolved in the brine sample at 30° C. andatmospheric pressure was determined from the measured vapor-liquidequilibrium data. A small correction was also made for the amount ofwater vapor that left the sample receiver and was collected in the gasbag. Normally, four samples were taken at a given condition, with thefirst being a purge and not included in the average reported in thetables in this report. The standard deviation of the other three sampleswas usually less than one percent of the average DME concentration.Rarely, the DME concentration in one of the samples would differ fromthe other two measurement by more than 2%. In this case, an additionalsample was withdrawn and processed.

After the measurement of the concentration of DME in the lower liquidphase at the vapor-liquid-liquid equilibrium pressure was completed,additional DME was added until the autoclave became liquid full. Thepressure was then raised in the autoclave to 3437 KPa (500 psia) byadding additional DME to the vessel. At this point, a constant pressurewas maintained as the contents of the autoclave were stirred. Afterstirring vigorously for twenty to thirty minutes, the stirrer was turnedoff and the aqueous and DME-rich phases in the autoclave were allowed toseparate. Then aliquots of the lower liquid (aqueous) phase were removedand analyzed as described above. Solubility data were also measured inthe same manner at 6895 KPa (1000 psia) and 10342 KPa (1500 psia).

After the liquid phase analyses were completed, the density of the lowerliquid phase was measured in a densimeter. The densimeter was calibratedusing nitrogen and boiled, deionized water. The nitrogen calibrationswere performed at the selected temperature and atmospheric pressure. Ahand pump was used to calibrate with water over the full range ofpressure encountered during the measurements. The density of water wastaken from the equation of state and database maintained by the Nationalinstitute for Standards and Technology (NIST). The calibration constantswere developed from the measured frequency data as a function oftemperature and pressure.

A set of samples was taken to determine the amounts of salt in the lowerliquid phase at 50° C., 17% brine, and the vapor-liquid-liquidequilibrium (VLLE) composition. These samples were taken into weighedvials and then evaporated to dryness. The two lower liquid samplesaveraged 17.0±0.1 wt % salt.

A second set of samples were taken of the upper liquid phase at 30° C.,20% brine, and 10342 KPa (1500 psia) to determine if a measureableamount of salt was in the upper liquid phase. These samples were alsotaken into vials and evaporated to dryness. No measureable salt wasfound in the upper liquid phase.

The experimental technique was validated by comparing the measured DMEsolubility in fresh water at 50° C. to published experimental data.Comparison for vapor-liquid and vapor-liquid-liquid equilibria indicatedthat the results of the experimental technique correlated well withpublished experimental data. There was no published data available forDME solubility in water at 50° C. in the liquid-liquid region althoughthe experimental liquid-liquid equilibrium data correlated withpublished liquid-liquid equilibrium data at higher temperatures (100 and121° C.). The impact of pressure on the solubility of DME in water doesnot vary significantly in this temperature range (50 to 121° C.): thesolubility of DME increases from 15.4 mol % (interpolated value) to 16.7mol % between 5000 and 10000 KPa at 50° C., it increases between 12.3mol % and 13.7 mol % at 100° C. in the same interval of pressure.

The DME solubility data measured experimentally is summarized in FIGS.4-6, where the salt concentration is reported on a gas-free basis.Dimethyl ether was strongly salted out by sodium chloride. At 30° C. thesolubility of DME in the aqueous phase decreases from 17.4 mol % infresh water to 3.71 mol % in a 20 wt. % brine. This effect is shown inFIG. 4 at 6895 KPa (1000 psia) in the liquid-liquid region for differenttemperatures. In the low pressure vapor-liquid region the presence ofsalt enhances the volatility of DME as shown in FIG. 5.

Increasing pressure increases the solubility of DME in fresh water from14.6 mol % to 16.8 mol % at 50° C. (between 3347 KPa and 10342 KPa (150and 1500 psia)). As brine concentration increases, the pressure effecton solubility becomes less pronounced as shown in FIG. 6. This is due tothe increasing density of the brine with salt concentration.

The Cubic-Plus-Association (CPA) equation of state model was extended toaccount for the effect of salt on the solubility of DME in the aqueousphase, and ultimately on its partitioning between brine and oil atreservoir conditions. CPA is available in Unisim Design through SPPTS3.0 and subsequent versions. A hypothetical component, SALT, wasintroduced into the model system to account for the effect of saltconcentration on DME solubility. Parameters describing water-SALTinteractions and thus characterizing the brine, were adjusted to theboiling point elevation, freezing point depression, and hydrate pointdepression data for NaCl brines. The parameters describing theinteractions of SALT with DME were adjusted to the experimental dataprovided above. The quality of the predictions are shown in FIGS. 7 a, 7b, 8 a, 8 b, and 9 over the whole range of conditions (vapor-liquid andliquid-liquid) and pressures (up to 10000 KPa).

Temperature-dependent interaction parameters (k₀ and k₁) for use in theCPA-SALT model were regressed from data at temperatures ranging from 30°C. to 120° C. The k₀ and k₁ parameters correspond to CPA binaryinteraction parameters BCPA0 and BCPA0T.

The CPA-SALT model also predicts the densities of the DME-brine phasewith reasonable accuracy as shown in FIGS. 10 and 11. The averagedeviation for all measured data points was 2.5%.

The solubility of DME in brines was plotted versus temperature atvarious brine concentrations in FIG. 12. The CPA-SALT model was used topredict the solubility of DME in the remaining brines at hightemperatures. The agreement between model predictions and experimentaldata at 10 wt. % salt is excellent.

The effect of salt on the partitioning of DME between oil and aqueousphases was predicted based on the CPA-SALT model, a key input toestimating DME efficiency as an EOR solvent. The model predicted thatthe partition coefficient of DME would increase by a factor 4 betweenfresh water and a 20 wt. % NaCl brine. The prediction indicated thatless DME can be injected in a single phase slug with highly concentratedbrines since the efficiency of DME should increase due to thepreferential partitioning into the oil enhanced by the presence of salt.

The CPA-SALT model was used to predict the impact of the presence ofsalt on the partitioning of DME between oil and aqueous phases.Predicted partitioning was found to increase by a factor 4 between thelimiting case of fresh water and a 20 wt. % NaCl Brine at 50° C. (oilwas modeled as nC16). Due to its reduced solubility in brine, less DMEcan be injected in a one-phase slug, but the higher partitioning allowsfor better miscibility of the DME in oil. The predicted partitioningalso indicates that DME may be recovered from residual oil using waterhaving a low salt content to recover DME from the residual oil,particularly in formations containing water having a relatively highsalt content.

The present invention is well adapted to attain the ends and advantagesmentioned as well as those that are inherent therein. The particularembodiments disclosed above are illustrative only, as the presentinvention may be modified and practiced in different but equivalentmanners apparent to those skilled in the art having the benefit of theteachings herein. Furthermore, no limitations are intended to thedetails of construction or design herein shown, other than as describedin the claims below. While compositions and methods are described interms of “comprising,” “containing,” or “including” various componentsor steps, the compositions and methods can also “consist essentially of”or “consist of” the various components and steps. Whenever a numericalrange with a lower limit and an upper limit is disclosed, any number andany included range falling within the range is specifically disclosed.In particular, every range of values (of the form, “from a to b,” or,equivalently, “from a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues. Whenever a numerical range having a specific lower limit only, aspecific upper limit only, or a specific upper limit and a specificlower limit is disclosed, the range also includes any numerical value“about” the specified lower limit and/or the specified upper limit.Also, the terms in the claims have their plain, ordinary meaning unlessotherwise explicitly and clearly defined by the patentee. Moreover, theindefinite articles “a” or “an”, as used in the claims, are definedherein to mean one or more than one of the element that it introduces.

What is claimed is:
 1. A system for producing oil from an undergroundformation comprising: a first well above the formation; a mechanism toinject an ether-containing formulation comprising into the formation,where the ether-containing formulation comprises an ether containingfrom 2 to 6 carbon atoms; a mechanism to inject an oil-immiscibleformulation into the formation where the oil-immiscible formulation hasa salt content of at most 5 wt. % and is comprised of water having atmost 5 wt. % salt content; and a mechanism to produce oil from theformation, wherein at least one of the mechanism to inject theether-containing formulation into the formation, the mechanism to injectan oil-immiscible formulation into the formation, or the mechanism toproduce oil from the formation is located at the first well.
 2. Thesystem of claim 1 wherein the ether-containing formulation comprisesfrom 5-100 wt. % dimethyl ether.
 3. The system of claim 1 wherein theoil-immiscible formulation comprises at least 80 wt. % water having asalt content of at most 5 wt. %.
 4. The system of claim 1 wherein theoil-immiscible formulation is comprised of water having a salt contentof at most 3 wt. %.
 5. The system of claim 1 wherein the first wellcomprises an array of from 5 to 500 wells.
 6. The system of claim 1further comprising a second well at a distance from the first well,wherein the mechanism to inject the ether-containing formulation intothe formation is located at the first well and the mechanism to produceoil from the formation is located at the second well.
 7. The system ofclaim 6 wherein the second well comprises an array of from 5 to 500wells.
 8. The method of claim 6 wherein the mechanism to inject theoil-immiscible formulation into the formation is located at the firstwell.
 9. The system of claim 6, further comprising a third well at adistance from the first well and at a distance from the second wellwherein the mechanism to inject the ether-containing formulation intothe formation is located at the first well and the mechanism to injectthe oil-immiscible formulation into the formation is located at thethird well.
 10. The system of claim 9 wherein the third well comprisesan array of from 5 to 500 wells.
 11. The system of claim 1 wherein themechanism for injecting the ether-containing formulation is located atthe first well and further comprising a mechanism for producing theether-containing formulation adjacent to the first well.
 12. The systemof claim 1 wherein the mechanism for producing oil from the formationalso produces the ether and water from the formation, where the systemfurther comprises a mechanism for separating a mixture of ether andwater from the oil produced by the mechanism for producing oil from theformation.
 13. The system of claim 1 wherein the mechanism for injectingthe oil-immiscible formulation into the formation is configured toinject the oil-immiscible formulation into the formation after theether-containing formulation is initially injected into the formation bythe mechanism for injecting the ether-containing formulation into theformation.
 14. A method for producing oil, comprising: injecting anether-containing formulation into a formation containing oil, where theether-containing formulation comprises an ether containing from 2 to 6carbons; injecting an oil-immiscible formulation into the formation,where the oil-immiscible formulation comprises water having a saltcontent of less than 5 wt. %; and producing oil from the formation. 15.The method of claim 14 further comprising the steps of: contacting theether-containing formulation with oil in the formation to mobilize oilin the formation wherein mobilizing the oil leaves an oil residuumcontaining an ether in the formation; and contacting the oil-immiscibleformulation with the oil residuum and separating a portion of the etherfrom the oil residuum into the oil-immiscible formulation.
 16. Themethod of claim 14 further comprising the steps of: producing the etherand water with the oil from the formation; and separating the ether andwater from the produced oil, ether, and water and injecting at least aportion of the separated ether and water into the formation.
 17. Themethod of claim 14 wherein the ether-containing formulation comprisesfrom 5-100 wt. % dimethyl ether.
 18. The method of claim 14 wherein theoil-immiscible formulation comprises at least 80 wt. % water having asalt content of at most 5 wt. %.
 19. The method of claim 14 wherein theoil-immiscible formulation is comprised of water having a salt contentof at most 3 wt. %.
 20. The method of claim 14 wherein theether-containing formulation comprises one or more hydrocarbons otherthan the ether, carbon dioxide, carbon monoxide, nitrogen, or mixturesthereof.
 21. The method of claim 14 further comprising heating theether-containing formulation prior to injecting the ether-containingformulation into the formation or while within the formation.
 22. Themethod of claim 14 wherein the ether-containing formulation is injectedinto the formation at a pressure of from 0 to 37,000 kilopascals abovethe formation pressure as determined immediately prior to injecting theether-containing formulation into the formation.
 23. The method of claim14 wherein the ether-containing formulation comprises the ether andwater, where the water in the ether-containing formulation has a saltcontent at least 1 wt. % greater than the salt content of theoil-immiscible formulation.
 24. The method of claim 14 furthercomprising contacting a sufficient amount of the ether-containingformulation with oil in the formation to increase the swelling factor ofthe oil in the formation.
 25. The method of claim 14 further comprisingcontacting a sufficient amount of the ether-containing formulation withoil in the formation to reduce the viscosity of the oil in theformation.
 26. The method of claim 14 further comprising contacting asufficient amount of the ether-containing formulation with oil in theformation to reduce the bubble point of the oil in the formation. 27.The method of claim 14 further comprising the step of converting the oilproduced from the formation into a material selected from the groupconsisting of a transportation fuel, a heating fuel, a lubricant, achemical, and a polymer.
 28. The method of claim 14 wherein theoil-immiscible formulation is injected into the formation afterinitially injecting the ether-containing formulation into the formation.